Sign in

You're signed outSign in or to get full access.

TR

Tamboran Resources Corp (TBN)·Q4 2025 Earnings Summary

Executive Summary

  • Q4 FY25 was operationally strong: record Beetaloo Basin IP90 of 6.7 MMcf/d from SS‑2H ST1 over a 5,483‑ft lateral; flow increased ~2% in the final 30 days without intervention, suggesting robust fracture conductivity and matrix contribution .
  • Regulatory/market milestones: Native Title and NT Government approvals under BUG legislation enable appraisal gas sales; SPCF site works and SPP construction advanced, keeping first gas from the SS Pilot Project on track for mid‑2026 .
  • Liquidity: Cash was $45.2M at quarter-end; pro forma cash and receivables totaled $71.1M after Tranche 2 PIPE ($11M) and $15M DWE acreage sale, with infrastructure debt funding for SPCF progressing .
  • Estimates context: Q4 EPS missed consensus (actual −$0.0030 vs consensus −$0.0017), while Q3 was a small beat; revenue consensus is $0 given pre‑revenue status. Values retrieved from S&P Global*.

What Went Well and What Went Wrong

What Went Well

  • Record production test performance: “Record Beetaloo Basin IP90 test of 6.7 MMcf/d … [with] ~2% increase in flow rate during final 30 days” — management highlights stable ~700 psi tubing pressure on a 44/64" choke .
  • Drilling execution: SS‑4H and SS‑5H reached TD with 10,000‑ft horizontals in ~27–28 days; program running in line with timeline and AFE (avg well cost ~$30M) .
  • Regulatory de‑risking and infrastructure: First approval under BUG legislation; SPCF bulk earthworks/piling completed and compressors delivered; APA started SPP construction with the hot-tap to AGP completed .

What Went Wrong

  • Tool failures/NPT: Management cited steerable systems/mud motor failures; best segments suggest potential 19‑day drill time, but reliability needs improvement .
  • SPCF funding not yet finalized: Remaining facility funding need is ~$70–$80M; company is pursuing infrastructure debt and potential sell‑down options .
  • Continued pre‑revenue and negative operating cash flow: Cash from operations remained negative, reflecting pilot build‑out costs and testing*. Values retrieved from S&P Global*.

Financial Results

MetricQ2 2025 (FY)Q3 2025 (FY)Q4 2025 (FY)
Net Income ($USD)−$14.17M −$6.66M −$10.18M*
Diluted EPS (Actual)−$0.00494*−$0.00156*−$0.00300*
Diluted EPS (Consensus)n/a−$0.00160*−$0.00168*
Revenues ($USD)n/a*n/a*n/a*
EBITDA ($USD)−$11.47M*−$6.09M*−$6.86M*
Cash from Operations ($USD)−$4.75M*−$14.30M −$6.43M*
Cash & Equivalents ($USD)$59.44M $25.64M $39.44M
Total Debt ($USD)$22.68M $26.87M $26.40M*

Notes:

  • EPS actual and consensus values, and cells marked with “*” are Values retrieved from S&P Global.
  • Traditional margin analyses are not applicable due to pre‑revenue status.

KPIs and Operational Metrics

KPIQ2 2025 (FY)Q3 2025 (FY)Q4 2025 (FY)
SS‑2H ST1 Stimulated Length (ft)5,483 5,483 5,483
SS‑2H ST1 Stages (#)35 35 35
Proppant Intensity (lb/ft)~2,706 ~2,706 ~2,706
IP30 (MMcf/d)n/aReported in June: 7.2 7.2
IP90 (MMcf/d)n/an/a6.7; exit 6.5 @ ~700 psi
SS‑3H Drill Days (10k ft lateral)25 25 —
SS‑4H/SS‑5H Drill Days (10k ft lateral)——27–28
SPCF ProgressEPCM awarded; permitting/design on track Equipment delivered; construction to commence post FID Bulk earthworks/piling complete; compressors on site
SPP ProgressBinding APA agreements; LLIs secured Pipe delivered to Darwin Hot-tap to AGP complete; construction commenced
Cash + Receivables ($USD)—Pro forma $96.0M Pro forma $71.1M

Guidance Changes

MetricPeriodPrevious GuidanceCurrent GuidanceChange
First Gas (SS Pilot Project)Mid‑20261H 2026 / mid‑2026 Mid‑2026 (maintained) Maintained
SPP CompletionEarly 20261H 2026 Early 2026 Maintained
SPCF CompletionMid‑2026Mid‑2026 Mid‑2026 (55% complete end‑Aug 2025) Maintained/Progressed
Stimulations (SS‑4H/5H/6H + SS‑3H)4Q25–1H264Q25–1H26 1H26 (SS‑4H first; zipper fracs planned) Maintained
Phase 2 Farmout Milestone2H 2025 process launch2H 2025 launch Target conclusion 1Q 2026 Clarified timeline
AFE per Pilot Well2H 2025~$28–30M (target <$25 days spud‑to‑TD) Avg ~$30M; potential to cut to ~$16M with local sand and efficiency Efficiency path reiterated

Earnings Call Themes & Trends

TopicQ2 FY25 Mentions (Dec qtr)Q3 FY25 Mentions (Mar qtr)Q4 FY25 Mentions (Jun qtr)Trend
Drilling efficiencySS‑3H drilled in 25 days; 43% faster vs SS‑2H Target <25 days for SS‑4/5/6; batch drilling plan SS‑4H/5H at 27–28 days; best segments imply ~19 days; NPT from tool failures Improving with room to reduce NPT
Flowback/soaking strategy62‑day soak plan for SS‑2H ST1 CoreLab model supports ~60‑day soak; type‑curve optimization IP90 +2% trend in last 30 days; deliberate choke management Validated longer soak approach
Infrastructure (SPCF/SPP)EPCM awarded; permits progressing Pipe/compressors delivered; construction slated SPCF site works completed; SPP construction started Executing to schedule
Regulatory approvals/Native TitleAPA binding agreements; line of credit Farmout set‑up; checkerboard complete BUG approval enables appraisal gas sales; Native Title consent Regulatory de‑risking advancing
Farmout (Phase 2)Evaluating; RBC engaged forthcoming RBC engaged; process launched Strong interest; target announcement ~1Q26 Moving to outcome
Local sand sourcing—Identified local frac‑quality sand; large cost impact Ongoing testing; plan to integrate with Liberty Progressing toward adoption
Markets (Domestic/LNG)MOU with Santos re DLNG Train 2; East Coast shortfall thesis Expanded Phase 1 and data center concept Pursuing NT domestic, East Coast, LNG; partner‑dependent timing Multi‑market optionality reaffirmed

Management Commentary

  • “We delivered and announced record flow rates … extremely flat decline … including a surprising 2% increase over the last 30 days of testing without downhole intervention or changes to the choke.” — Richard Stoneburner, Chairman & Interim CEO .
  • “We reached TD on the second of the three wells, delivering record drilling speeds through the horizontal section … batch drilling with H&P FlexRig®.” — Stoneburner .
  • “We received consent from native title holders … the first approval … under the beneficial use of gas legislation, allowing us to sell appraisal gas for three years.” — Stoneburner .
  • “Cash and receivables are $71.1 million … progressing discussions with financiers to secure the remaining funding of the SPCF.” — Stoneburner ; corroborated in presentation .

Q&A Highlights

  • Drilling reliability and timing: Management detailed downhole tool failures but indicated best‑segment drill time could be ~19 days, with further gains planned via mud system, directional tools, and multi‑well pad efficiencies .
  • Completion/flow test plan: SS‑4H stimulation imminent; 30‑day flow test and soak strategy consistent with prior wells; deliberate choke management highlighted .
  • SPCF funding: Pursuing infrastructure debt; ~$70–$80M remaining; considering sell‑down/expansion to meet unmet local demand .
  • Farmout timing: Target announcement around 1Q26; broad interest from IOCs/strategics .
  • Regulatory/ILUA: Three‑year BUG window avoids flaring while ILUA consultations proceed toward production license; normal consultation may take up to ~3 years .

Estimates Context

  • Q4 FY25 EPS missed consensus: Actual −$0.00300 vs consensus −$0.00168 (miss of −$0.00132); Q3 FY25 was a modest beat (Actual −$0.00156 vs consensus −$0.00160). Revenue consensus remains $0 given pre‑revenue status. Values retrieved from S&P Global*.
  • Implications: Near‑term estimate adjustments likely to reflect sustained pre‑revenue, infrastructure spend, and financing costs until mid‑2026 first gas. Longer‑dated models should incorporate operational de‑risking (IP metrics, drill times) and timing of farmout/SPCF financing .

Key Takeaways for Investors

  • Operational de‑risking is tangible: Record IP90 with stable pressure and late‑period flow increase supports improving type‑curve assumptions for Mid Velkerri B development .
  • Execution to first gas remains on schedule: BUG approvals, SPCF site progress, and SPP construction underpin mid‑2026 startup; watch remaining SPCF financing to close the loop .
  • Cost trajectory credible: Local sand and batch completions can lower well costs materially (management cited potential ~$3.5M per well savings from sand), with multi‑well pad efficiencies to follow .
  • Farmout is a key 1Q26 catalyst: A successful deal could add cash/carry, accelerate Phase 2 delineation, and validate basin economics; monitor partner quality and terms .
  • Pre‑revenue financials will continue to pressure EPS/OCF until mid‑2026; focus on liquidity runway (cash + receivables) and project financing developments .
  • Multi‑market strategy intact: NT domestic, East Coast, and LNG options give long‑term offtake flexibility; partner preferences may shape phasing .
  • Regulatory momentum: First BUG approval and Native Title consent reduce commercialization risk; ILUA process underway for longer‑term production licensing .

Footnotes:

  • Cells marked with “*” are Values retrieved from S&P Global.
  • All other facts and figures are sourced from Q4 FY25 8‑K press release/presentation and earnings call materials as cited.